Aromatic hydrocarbons, particularly benzene, toluene, ethylbenzene and xylenes, are important commodity chemicals in the petrochemical industry. Currently, aromatics are mostly frequently produced from petroleum-based feedstocks by a variety of processes, including catalytic reforming and catalytic cracking. However, as the world supplies of petroleum feedstocks decrease, there is a growing need to find alternative sources of aromatic hydrocarbons.
One possible alternative source of aromatic hydrocarbons is methane, which is the major constituent of natural gas and biogas. World reserves of natural gas are constantly being upgraded and more natural gas is currently being discovered than oil. Because of the problems associated with transportation of large volumes of natural gas, sometimes a significant portion of the natural gas produced along with oil at remote places is flared and wasted. Hence the conversion of alkanes contained in natural gas directly to higher hydrocarbons, such as aromatics, is a particularly desirable method of upgrading natural gas, providing the attendant technical difficulties can be overcome.
A large majority of the existing processes for converting methane to liquid hydrocarbons involve first conversion of the methane to synthesis gas, a blend of H2 and CO. However, the production of synthesis gas is capital and energy intensive; therefore routes that do not require synthesis gas generation are preferred.
A number of other processes have been proposed for directly converting methane to higher hydrocarbons, such as catalytic oxidative coupling of methane to olefins followed by the catalytic conversion of the olefins to liquid hydrocarbons, including aromatic hydrocarbons. See, for example, U.S. Pat. No. 5,336,825. However, oxidative coupling methods suffer from the problem that they involve highly exothermic reactions (and thus are exposed to potentially hazardous methane combustion reactions) and they generate large quantities of environmentally sensitive carbon oxides.
A potentially more attractive route for the direct conversion of methane to higher hydrocarbons is by way of dehydroaromatization, which is a reductive coupling process in which methane is converted to aromatic hydrocarbons, such as benzene, toluene, and naphthalene (commonly referred to collectively as “BTN”), along with hydrogen, using a supported metal catalyst. See, for example, U.S. Pat. No. 5,026,937. However, not only does this process produce large quantities of hydrogen (9 moles of hydrogen for every mole of benzene) but thermodynamic considerations dictate that only a limited amount of the methane feed that can be converted to aromatic products at economically viable operating conditions. Thus, to be successful, any commercial methane dehydroaromatization process must make provision for the separation and use of large quantities of unreacted methane and by-product hydrogen.
For example, recognizing that most natural gas sources also contain large quantities of CO2, U.S. Patent Publication 2007/0260098 discloses a process for converting methane to higher hydrocarbons including aromatic hydrocarbons, in which a methane-containing feed is contacted with a dehydroaromatization catalyst, conveniently molybdenum, tungsten and/or rhenium or a compound thereof of ZSM-5 or an aluminum oxide, under conditions effective to convert the methane to aromatic hydrocarbons and produce a first effluent stream comprising aromatic hydrocarbons and H2, wherein said first effluent stream comprises at least 5 wt % more aromatic rings than said feed. At least part of the H2 from the first effluent stream is then reacted with an oxygen-containing species, such as CO2, to produce a second effluent stream having a reduced H2 content compared with the first effluent stream.
Japanese Unexamined Patent Publication No. 2006016353 discusses methane dehydroaromatization and the effect of sulfur on this reaction system. The catalyst and reaction system of this prior art suffers from very significant catalyst performance deterioration when sulfur is included in the methane containing feed at levels above 10 ppm H2S. For a feed containing 100 ppm H2S, benzene yields over the catalyst life cycle are decreased to about one quarter of the yields with no sulfur present.
Another major use of methane-containing feeds is in the production of pipeline gas and liquefied natural gas (LNG). Pipeline gas is natural gas which has been purified sufficiently to allow its direct use as a fuel or chemical feedstock by both retail and industrial consumers. LNG is natural gas which has been purified and cooled to −260° F. (−162° C.). At this temperature, natural gas condenses into a liquid, which takes up to 600 times less space than in the gaseous form, making it feasible to transport the product over long distances. Both pipeline gas and LNG typically contain at least 85 mol % methane with the balance being higher chain alkanes and so to produce them it is necessary to reduce most impurities in the natural gas feed to very low levels. For example, acid gases, such H2S, mercaptans and carbon dioxide, that are corrosive to the LNG plant and other equipment must be reduced to extremely low levels, for example H2S levels often have to be below 4 ppm by volume. In addition, water, which could freeze and cause equipment blockage, must be removed, generally to less than 1 ppb in LNG. Similarly, butane and heavier hydrocarbons, which could freeze like water and also have value as chemical feedstocks, are removed typically to levels below 1 to 2% by volume.
To date, some limited proposals have been made to integrate LNG production with conversion of methane to liquid hydrocarbons.
For example, U.S. Pat. No. 7,451,618 discloses a process for liquefying natural gas comprising (a) passing the natural gas at liquefaction pressure through the product side of a main heat exchanger; (b) introducing cooled liquefied refrigerant at refrigerant pressure in the cold side of the main heat exchanger, allowing the cooled refrigerant to evaporate at the refrigerant pressure in the cold side of the main heat exchanger to obtain vaporous refrigerant at refrigerant pressure, and removing vaporous refrigerant from the cold side of the main heat exchanger; (c) removing the liquefied gas at liquefaction pressure from the product side of the main heat exchanger; (d) allowing the cooled liquefied gas to expand to a lower pressure to obtain expanded fluid; (e) supplying the expanded fluid to a separator vessel; (f) withdrawing from the bottom of the separator vessel a liquid product stream; (g) withdrawing from the top of the separator vessel a gaseous stream; (h) introducing the gaseous stream obtained in step (g) as feed and/or fuel in the process for the preparation of liquid hydrocarbons, which process for the preparation of hydrocarbons involves converting a light hydrocarbonaceous feedstock into synthesis gas, followed by catalytic conversion of the synthesis gas into liquid hydrocarbons.
However, while the process of the '618 patent claims efficiencies associated with integration of two processes (natural gas liquefaction and liquid hydrocarbon synthesis), it is still inherently inefficient for at least two reasons, one being the large pressure differential between the liquefaction effluent stream and the preferred operating pressure for the liquid hydrocarbon synthesis, and another being that production of synthesis gas as an intermediate step in the production of liquid hydrocarbons is capital and energy intensive. Accordingly, a more efficient integration of methane conversion technologies with gas liquefaction would be of value.
According to the invention, it has now been found that by integrating methane dehydroaromatization into the feed gas conditioning process of LNG and pipeline gas production, it is possible to significantly reduce the amount of the purification required in the conditioning process. In particular, it is found that many contaminants which are highly problematic in LNG and pipeline gas production, such as water, mercaptans, H2S, and CO2, can be tolerated at higher levels and/or are beneficial and/or are converted to less injurious components in the methane dehydroaromatization process of the present invention. It has been discovered that, unlike the prior-art dehydroaromatization process discussed above, the present dehydroaromatization process can tolerate high levels of sulfur in the range of 100 vppm to 1000 vppm. Since feed gas purification is one of the costliest processes involved in LNG and pipeline gas production, any reduction in the impurity levels required in the feed is potentially of enormous economic benefit. In addition, by integrating methane dehydroaromatization with LNG and pipeline gas production, part of the methane in the natural gas feed is upgraded to higher value aromatic hydrocarbons.